Contamination prediction of downhole pumpout and sampling

ABSTRACT

A method may comprise positioning a downhole fluid sampling tool into a wellbore; performing a pressure test operation within the wellbore; performing a pumpout operation within the wellbore; identifying one or more formation parameters at least in part from the at least one pressure test operation or the at least one pumpout operation; building a correlation model that relates a pumpout trend to the one or more formation parameters; determining a time when the downhole fluid sampling tool takes a clean fluid sample utilizing at least the correlation model; and acquiring the clean fluid sample with the downhole fluid sampling tool from the wellbore. Additionally, a system may comprise a downhole fluid sampling tool configured to: perform a pressure test operation within a wellbore; and perform a pumpout operation within the wellbore.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.17/237,851, filed Apr. 22, 2021, which is a continuation of U.S. patentapplication Ser. No. 16/447,808, filed Jun. 20, 2019, which areincorporated by reference herein in their entirety.

BACKGROUND

During oil and gas exploration, many types of information may becollected and analyzed. The information may be used to determine thequantity and quality of hydrocarbons in a reservoir and to develop ormodify strategies for hydrocarbon production. For instance, theinformation may be used for reservoir evaluation, flow assurance,reservoir stimulation, facility enhancement, production enhancementstrategies, and reserve estimation. One technique for collectingrelevant information involves collecting a formation fluid sample at anyspecified depth within a wellbore. The acquisition of representativeformation fluid samples is essential for proper reservoir management anddevelopment. However, because of overbalance pressure in the mud column,mud filtrate invades and contaminates the reservoir fluid during thedrilling process, before the mudcake around the wellbore is properlyformed.

Currently, methods and systems for identifying and capturing cleanformation fluid samples can be limited by pumpout data identified duringa pumpout operation. Additionally, current methods and systems can usecurve fitting methods to determine when a clean fluid sample may betaken at a moment in time. However, curve fitting methods can rely onthe assumption that when the properties being monitored does not changesignificantly as the pumping continues, the contamination level is low.However, this may also be because of steady state effect even at highcontamination levels.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the examples of thepresent disclosure, and should not be used to limit or define thedisclosure;

FIG. 1 is a schematic diagram of an example of a formation testing toolon a wireline;

FIG. 2 is a schematic diagram of an example of the formation testingtool on a drill string;

FIG. 3 is a schematic drawing of the formation testing tool; and

FIG. 4 is a flow chart for identifying a clean fluid sample.

DETAILED DESCRIPTION

This disclosure is directed to subterranean operations and, moreparticularly, to methods for operating a downhole formation testing toolto capture clean sample fluids after preforming a pressure testoperation and a pumpout operation. By utilizing the measurements andproperties found during the pressure test operation and the pumpoutoperation, the time at which it may be possible to capture a clean fluidmay be identified.

FIG. 1 is a schematic diagram of formation testing tool 100 on aconveyance 102 in accordance with example embodiment. As illustrated,wellbore 104 may extend through subterranean formation 106. In examples,reservoir fluid may be contaminated with well fluid (e.g., drillingfluid) from wellbore 104. As described herein, the fluid sample may beanalyzed to determine fluid contamination and other fluid properties ofthe reservoir fluid. As illustrated, a wellbore 104 may extend throughsubterranean formation 106. While the wellbore 104 is shown extendinggenerally vertically into the subterranean formation 106, the principlesdescribed herein are also applicable to wellbores that extend at anangle through the subterranean formation 106, such as horizontal andslanted wellbores. For example, although FIG. 1 shows a vertical or lowinclination angle well, high inclination angle or horizontal placementof the well and equipment is also possible. It should further be notedthat while FIG. 1 generally depicts a land-based operation, thoseskilled in the art will readily recognize that the principles describedherein are equally applicable to subsea operations that employ floatingor sea-based platforms and rigs, without departing from the scope of thedisclosure.

As illustrated, a hoist 108 may be used to run formation testing tool100 into wellbore 104. Hoist 108 may be disposed on a vehicle 110. Hoist108 may be used, for example, to raise and lower conveyance 102 inwellbore 104. While hoist 108 is shown on vehicle 110, it should beunderstood that conveyance 102 may alternatively be disposed from ahoist 108 that is installed at surface 112 instead of being located onvehicle 110. Formation testing tool 100 may be suspended in wellbore 104on conveyance 102. Other conveyance types may be used for conveyingformation testing tool 100 into wellbore 104, including coiled tubingand wired drill pipe, for example. Formation testing tool 100 mayinclude a tool body 114, which may be elongated as shown on FIG. 1 .Tool body 114 may be any suitable material, including without limitationtitanium, stainless steel, alloys, plastic, combinations thereof, andthe like. Formation testing tool 100 may further include one or moresensors 116 for measuring properties of the fluid sample, reservoirfluid, wellbore 104, subterranean formation 106, or the like. Inexamples, formation testing tool 100 may also include a fluid analysismodule 118, which may be operable to process information regarding fluidsample, as described below. Formation testing tool 100 may be used tocollect fluid samples from subterranean formation 106 and may obtain andseparately store different fluid samples from subterranean formation106.

In examples, fluid analysis module 118 may include at least one sensorthat may continuously monitor a reservoir fluid. Such sensors includeoptical sensors, acoustic sensors, electromagnetic sensors, conductivitysensors, resistivity sensors, selective electrodes, density sensors,mass sensors, thermal sensors, chromatography sensors, viscositysensors, bubble point sensors, fluid compressibility sensors, flow ratesensors. Sensors may measure a contrast between drilling fluid filtrateproperties and formation fluid properties.

In examples, fluid analysis module 118 may be a gas chromatographyanalyzer (GC). A gas chromatography analyzer may separate and analyzecompounds that may be vaporized without decomposition. Fluid samplesfrom wellbore 104 may be injected into a GC column and vaporized.Different compounds may be separated due to their retention timedifference in the vapor state. Analyses of the compounds may bedisplayed in GC chromatographs. In examples, a mixture of formationfluid and drilling fluid filtrate may be separated and analyzed todetermine the properties within the formation fluid and drilling fluidfiltrate.

Fluid analysis module 118 may be operable to derive properties andcharacterize the fluid sample. By way of example, fluid analysis module118 may measure absorption, transmittance, or reflectance spectra andtranslate such measurements into component concentrations of the fluidsample, which may be lumped component concentrations, as describedabove. The fluid analysis module 118 may also measure gas-to-oil ratio,fluid composition, water cut, live fluid density, live fluid viscosity,formation pressure, and formation temperature. Fluid analysis module 118may also be operable to determine fluid contamination of the fluidsample and may include any instrumentality or aggregate ofinstrumentalities operable to compute, classify, process, transmit,receive, retrieve, originate, switch, store, display, manifest, detect,record, reproduce, handle, or utilize any form of information,intelligence, or data for business, scientific, control, or otherpurposes. For example, fluid analysis module 118 may include randomaccess memory (RAM), one or more processing units, such as a centralprocessing unit (CPU), or hardware or software control logic, ROM,and/or other types of nonvolatile memory.

Any suitable technique may be used for transmitting signals from theformation testing tool 100 to surface 112. As illustrated, acommunication link 120 (which may be wired or wireless, for example) maybe provided that may transmit data from formation testing tool 100 to aninformation handling system 122 at surface 112. Information handlingsystem 122 may include a processing unit 124, a monitor 126, an inputdevice 128 (e.g., keyboard, mouse, etc.), and/or computer media 130(e.g., optical disks, magnetic disks) that can store code representativeof the methods described herein. Information handling system 122 may actas a data acquisition system and possibly a data processing system thatanalyzes information from formation testing tool 100. For example,information handling system 122 may process the information fromformation testing tool 100 for determination of fluid contamination.Information handling system 122 may also determine additional propertiesof the fluid sample (or reservoir fluid), such as componentconcentrations, pressure-volume-temperature properties (e.g., bubblepoint, phase envelop prediction, etc.) based on the fluidcharacterization. This processing may occur at surface 112 in real-time.Alternatively, the processing may occur downhole hole or at surface 112or another location after recovery of formation testing tool 100 fromwellbore 104. Alternatively, the processing may be performed by aninformation handling system in wellbore 104, such as fluid analysismodule 118. The resultant fluid contamination and fluid properties maythen be transmitted to surface 112, for example, in real-time.

It should be noted that in examples a gas chromatographer 132 may bedisposed on surface 112 and analyze samples captures by formationtesting tool 100. For example, fluid analysis module 118 may capturefluid samples and bring them to the surface 112 for analysis at thewellsite. As illustrated, gas chromatographer 132 may be disposed invehicle 110. However, gas chromatographer 132 may be a standaloneassembly that may be available at the wellsite. Additionally,information handling system 122 may be connected to gas chromatographer132 through communication link 120. In examples, gas chromatographer 132may operate and function as described above.

Referring now to FIG. 2 , a schematic diagram is shown of formationtesting tool 100 disposed on a drill string 200 in a drilling operationin accordance with example embodiments. Formation testing tool 100 maybe used to obtain a fluid sample, for example, a fluid sample of areservoir fluid from subterranean formation 106. The reservoir fluid maybe contaminated with well fluid (e.g., drilling fluid) from wellbore104. As described herein, the fluid sample may be analyzed to determinefluid contamination and other fluid properties of the reservoir fluid.As illustrated, a wellbore 104 may extend through subterranean formation106. While the wellbore 104 is shown extending generally vertically intothe subterranean formation 106, the principles described herein are alsoapplicable to wellbores that extend at an angle through the subterraneanformation 106, such as horizontal and slanted wellbores. For example,although FIG. 2 shows a vertical or low inclination angle well, highinclination angle or horizontal placement of the well and equipment isalso possible. It should further be noted that while FIG. 2 generallydepicts a land-based operation, those skilled in the art will readilyrecognize that the principles described herein are equally applicable tosubsea operations that employ floating or sea-based platforms and rigs,without departing from the scope of the disclosure.

As illustrated, a drilling platform 202 may support a derrick 204 havinga traveling block 206 for raising and lowering drill string 200. Drillstring 200 may include, but is not limited to, drill pipe and coiledtubing, as generally known to those skilled in the art. A kelly 208 maysupport drill string 200 as it may be lowered through a rotary table210. A drill bit 212 may be attached to the distal end of drill string200 and may be driven either by a downhole motor and/or via rotation ofdrill string 200 from the surface 112. Without limitation, drill bit 212may include, roller cone bits, PDC bits, natural diamond bits, any holeopeners, reamers, coring bits, and the like. As drill bit 212 rotates,it may create and extend wellbore 104 that penetrates varioussubterranean formations 106. A pump 214 may circulate drilling fluidthrough a feed pipe 216 to kelly 208, downhole through interior of drillstring 200, through orifices in drill bit 212, back to surface 112 viaannulus 218 surrounding drill string 200, and into a retention pit 220.

Drill bit 212 may be just one piece of a downhole assembly that mayinclude one or more drill collars 222 and formation testing tool 100.Formation testing tool 100, which may be built into the drill collars222 may gather measurements and fluid samples as described herein. Oneor more of the drill collars 222 may form a tool body 114, which may beelongated as shown on FIG. 2 . Tool body 114 may be any suitablematerial, including without limitation titanium, stainless steel,alloys, plastic, combinations thereof, and the like. Formation testingtool 100 may be similar in configuration and operation to formationtesting tool 100 shown on FIG. 1 except that FIG. 2 shows formationtesting tool 100 disposed on drill string 200. Alternatively, thesampling tool may be lowered into the wellbore after drilling operationson a wireline.

Formation testing tool 100 may further include one or more sensors 116for measuring properties of the fluid sample reservoir fluid, wellbore104, subterranean formation 106, or the like. The properties of thefluid are measured as the fluid passes from the formation through thetool and into either the wellbore or a sample container. As fluid isflushed in the near wellbore region by the mechanical pump, the fluidthat passes through the tool generally reduces in drilling fluidfiltrate content, and generally increases in formation fluid content.Formation testing tool 100 may be used to collect a fluid sample fromsubterranean formation 106 when the filtrate content has been determinedto be sufficiently low. Sufficiently low depends on the purpose ofsampling. For some laboratory testing below 10% drilling fluidcontamination is sufficiently low, and for other testing below 1%drilling fluid filtrate contamination is sufficiently low. Sufficientlylow also depends on the nature of the formation fluid such that lowerrequirements are generally needed, the lighter the oil as designatedwith either a higher GOR or a higher API gravity. Sufficiently low alsodepends on the rate of cleanup in a cost benefit analysis since longerpumpout times required to incrementally reduce the contamination levelsmay have prohibitively large costs. As previously described, the fluidsample may include a reservoir fluid, which may be contaminated with adrilling fluid or drilling fluid filtrate. Formation testing tool 100may obtain and separately store different fluid samples fromsubterranean formation 106 with fluid analysis module 118. Fluidanalysis module 118 may operate and function in the same manner asdescribed above. However, storing of the fluid samples in the formationtesting tool 100 may be based on the determination of the fluidcontamination. For example, if the fluid contamination exceeds atolerance, then the fluid sample may not be stored. If the fluidcontamination is within a tolerance, then the fluid sample may be storedin the formation testing tool 100.

As previously described, information from formation testing tool 100 maybe transmitted to an information handling system 122, which may belocated at surface 112. As illustrated, communication link 120 (whichmay be wired or wireless, for example) may be provided that may transmitdata from formation testing tool 100 to an information handling system111 at surface 112. Information handling system 140 may include aprocessing unit 124, a monitor 126, an input device 128 (e.g., keyboard,mouse, etc.), and/or computer media 130 (e.g., optical disks, magneticdisks) that may store code representative of the methods describedherein. In addition to, or in place of processing at surface 112,processing may occur downhole (e.g., fluid analysis module 118). Inexamples, information handling system 122 may perform computations toestimate clean fluid composition.

As previously described above, a gas chromatographer 132 (e.g.,referring to FIG. 1 ) may be disposed on surface 112 and analyze samplescaptures by downhole fluid sampling tool 100. For example, fluidanalysis module 118 may capture fluid samples and bring them to thesurface 112 for analysis at the wellsite. As illustrated, gaschromatographer 132 may be a standalone assembly that may be availableat the wellsite. Additionally, information handling system 122 may beconnected to gas chromatographer 132 through communication link 120. Inexamples, gas chromatographer 132 may operate and function as describedabove.

FIG. 3 is a schematic of downhole fluid sampling tool 100, which may beused for fluid sampling operations and/or pressure test operations. Inexamples, downhole fluid sampling tool 100 includes a power telemetrysection 302 through which the tool communicates with other actuators andsensors 116 in drill string 200 or conveyance 102 (e.g., referring toFIGS. 1 and 2 ), the drill string's telemetry section 302, and/ordirectly with a surface telemetry system (not illustrated). In examples,power telemetry section 302 may also be a port through which the variousactuators (e.g. valves) and sensors (e.g., temperature and pressuresensors) in the downhole fluid sampling tool 100 may be controlled andmonitored. In examples, power telemetry section 302 includes a computerthat exercises the control and monitoring function. In one embodiment,the control and monitoring function is performed by a computer inanother part of the drill string or wireline tool (not shown) or byinformation handling system 122 on surface 112 (e.g., referring to FIGS.1 and 2 ).

In examples, downhole fluid sampling tool 100 includes a dual probesection 304, which extracts fluid from the reservoir and delivers it toa channel 306 that extends from one end of downhole fluid sampling tool100 to the other. Without limitation, dual probe section 304 includestwo probes 318, 320 which may extend from downhole fluid sampling tool100 and press against the inner wall of wellbore 104 (e.g., referring toFIG. 1 ). Probe channels 322, 324 may connect probes 318, 320 to channel306. The high-volume bidirectional pump 312 may be used to pump fluidsfrom the reservoir, through probe channels 322, 324 and to channel 306.Alternatively, a low volume pump 326 may be used for this purpose. Twostandoffs or stabilizers 328, 330 hold downhole fluid sampling tool 100in place as probes 318, 320 press against the wall of wellbore 104. Inexamples, probes 318, 320 and stabilizers 328, 330 may be retracted whendownhole fluid sampling tool 100 may be in motion and probes 318, 320and stabilizers 328, 330 may be extended to sample the formation fluidsat any suitable location in wellbore 104. Other probe sections includefocused sampling probes, oval probes, or packers.

In examples, channel 306 may be connected to other tools disposed ondrill string 200 or conveyance 102 (e.g., referring to FIGS. 1 and 2 ).In examples, downhole fluid sampling tool 100 may also include a quartzgauge section 308, which may include sensors to allow measurement ofproperties, such as temperature and pressure, of fluid in channel 306.Additionally, downhole fluid sampling tool 100 may include aflow-control pump-out section 310, which may include a high-volumebidirectional pump 312 for pumping fluid through channel 306. Inexamples, downhole fluid sampling tool 100 may include two multi-chambersections 314, 316, referred to collectively as multi-chamber sections314, 316 or individually as first multi-chamber section 314 and secondmulti-chamber section 316, respectively.

In examples, multi-chamber sections 314, 316 may be separated fromflow-control pump-out section 310 by sensor section 332, which may houseat least one sensor 334. Sensor 334 may be displaced within sensorsection 332 in-line with channel 306 to be a “flow through” sensor. Inalternate examples, sensor 334 may be connected to channel 306 via anoffshoot of channel 306. Without limitation, sensor 334 may includeoptical sensors, acoustic sensors, electromagnetic sensors, conductivitysensors, resistivity sensors, selective electrodes, density sensors,mass sensors, thermal sensors, chromatography sensors, viscositysensors, bubble point sensors, fluid compressibility sensors, flow ratesensors, microfluidic sensors, selective electrodes such as ionselective electrodes, and/or combinations thereof. In examples, sensor334 may operate and/or function to measure drilling fluid filtrate,discussed further below.

Additionally, multi-chamber section 314, 316 may comprise access channel336 and chamber access channel 338. Without limitation, access channel336 and chamber access channel 338 may operate and function to eitherallow a solids-containing fluid (e.g., mud) disposed in wellbore 104 inor provide a path for removing fluid from downhole fluid sampling tool100 into wellbore 104. As illustrated, multi-chamber section 314, 316may comprise a plurality of chambers 340. Chambers 340 may be samplingchamber that may be used to sample wellbore fluids, formation fluids,and/or the like during measurement operations. It should be noted thatformation testing tool 100 may also be used in pressure testingoperations.

For example, during pressure testing operations, probes 318, 320 may bepressed against the inner wall of wellbore 104 (e.g., referring to FIG.1 ). Pressure may increase at probes 318, 320 due to formation 106(e.g., referring to FIG. 1 or 2 ) exerting pressure on probes 318, 320.As pressure rises and reaches a predetermined pressure, valves 342 opensso as to close equalizer valve 344, thereby isolating fluid passageway346 from the annulus 218. In this manner, valve 342 ensures thatequalizer valve 344 closes only after probes 318, 320 has enteredcontact with mudcake (not illustrated) that is disposed against theinner wall of wellbore 104. In examples, as probes 318, 320 are pressedagainst the inner wall of wellbore 104, the pressure rises and closesthe equalizer valve in fluid passageway 346, thereby isolating the fluidpassageway 346 from the annulus 218. In this manner, the equalizer valvein fluid passageway 346 may close before probes 318, 320 may haveentered contact with the mudcake that lines the inner wall of wellbore104. Fluid passageway 346, now closed to annulus 218, is in fluidcommunication with low volume pump 326.

As low volume pump 326 is actuated, formation fluid may thus be drawnthrough probe channels 322, 324 and probes 318, 320. The movement of lowvolume pump 326 lowers the pressure in fluid passageway 346 to apressure below the formation pressure, such that formation fluid isdrawn through probe channels 322, 324 and probes 318, 320 and into fluidpassageway 346. The pressure of the formation fluid may be measured influid passageway 346 while probes 318, 320 serves as a seal to preventannular fluids from entering fluid passageway 346 and invalidating theformation pressure measurement.

With low volume pump 326 in its fully retracted position and formationfluid drawn into fluid passageway 346, the pressure will stabilize andenable pressure transducers 348 to sense and measure formation fluidpressure. The measured pressure is transmitted to information handlingsystem 122 disposed on formation testing tool 100 and/or it may betransmitted to the surface via mud pulse telemetry or by any otherconventional telemetry means to an information handling system 122disposed on surface 112.

During this interval, pressure transducers 348 may continuously monitorthe pressure in fluid passageway 346 until the pressure stabilizes, orafter a predetermined time interval. When the measured pressurestabilizes, or after a predetermined time interval, for example at 1800psi, and is sensed by pressure transducer 348 the drawdown operation maybe complete. Once complete, fluid for the pressure test in fluidpassageway 346 may be dispelled from formation testing tool 100 throughthe opening and/or closing of valves 342 and/or equalizer valve 344 aslow volume pump 326 returns to a starting position.

During formation sampling operations, as described above, theacquisition of representative formation fluid samples may allow forproper reservoir management and development. However, because ofoverbalance pressure in the mud column, mud filtrate invades andcontaminates the reservoir fluid during the drilling process, before themudcake around the wellbore is properly formed. Although water-based mud(WBM) is immiscible with formation fluid, oil-based mud (OBM) ismiscible with it. Samples with OBM contamination levels greater than atleast 10% for oils and 3% for volatile oils and gas condensates may beconsidered unusable because the OBM contamination alters the formationfluid properties and phase behavior; this alteration prevents anaccurate characterization of the reservoir fluid. General targets arebelow 5% contamination for oils, and below 2% contamination for volatileoils and less than 1% contamination for condensates.

During fluid sampling operations, it may be difficult to avoidcontamination. It should be noted that open hole sampling is usually asingle opportunity event. For example, after sample are acquired, asdescribed above, the samples may be taken to a laboratory for analysis.After analysis is complete, it may not be possible to acquire additionalsamples. Consequently, during fluid sampling operations contaminatedfluid may be cleaned up before taking a fluid sample. Cleanup times maydepend on multiple parameters, including formation permeability, fluidviscosity, depth of invasion, and wellbore mud column overbalancepressure. Current methods for predicting contamination may rely on curvefitting to a single (in some cases multiple) property such as density orgas oil ratio (“GOR”). Curve fitting relies on the assumption that whenthe properties being monitored do not change significantly as thepumping continues, the contamination level is low. However, this mayalso be because of steady state effect even at high contamination level.Additionally, contamination value from curve fitting method may besensitive to data selection and may depend on the endmember filtrate andformation fluid properties which may not be measured directly eitherdownhole or in the laboratory.

During fluid sampling operations, a pressure test operation may beperformed, which may aide in predicting contamination using density andformation properties such as drawdown mobility (or a transient mobilitysuch as provided by exact mobility), formation pressure, overbalance,drawdown pressures, porosity etc. By combining multiple parameters suchfluid density, drawdown mobility, formation pressure, drawdown andoverbalance pressure, predicted contamination value from a pressuretest, described above, clean fluid samples may be identified. Moreover,the workflow described below may not be dependent on end memberproperties. The workflow is based on constraining pumpout data withformation properties from pressure testing data. As an overview of theworkflow, a large dataset of pumpout volume, density and formationproperties data acquired from different regions of the world are used todevelop a predictive model using for instance a machine learningapproach. As noted below, the machine learning approach may also beperformed by a mapping schemes that may allow for a prediction ofoutput. For example, an output may be predicted based at least in parton the input. Without limitation, the density may be represented asoptimized parameters of an inverse or a double exponential equationfitted to the density curve. The contamination estimation method hasbeen validated with several dataset from different region of the world.

As illustrated in FIG. 4 , workflow 400 may combine pumpout data withthe formation properties data obtained from pressure testing. Workflow400 may begin with block 402. In block 402 a pressure test drawdownoperation may be performed at a location of a formation pumpoutoperation. It should be noted that the pressure test drawdown operationmay be performed within an area no larger than 2% away from theformation pumpout operation. During this operation, the pressure bledoff prior to the drawdown may be recorded as a function of set pressure.In examples, a function of set pressure may be defined as monitoringchanges in pressure to a control fluid. After bleeding off pressureprior to a drawdown, a pressure test operation may be performed.

In block 404, during the pressure test operations, a dataset may becompiled which may include formation properties including formationpressure, wellbore pressure, drawdown (or transient) mobility, drawdownpressure, blead off pressure (or other mud cake properties), pumpoutvolume, fluid formation fluid density and viscosity, filtrate density,and viscosity. These formation properties may be used to produce acontamination profile at the location (i.e., pumpout station) in whichthe pressure test operation and formation pumpout operations have takenplace. In block 406, the corresponding contamination level may bemeasured and/or computed as a function of pumpout volume in capturedsamples from the corresponding pumpout stations. It should be noted thatworkflow 400 may be performed at any number of pumpout stations withinthe wellbore. In block 408, pumpout trends may be parameterized with atleast one ubiquitous pumpout model such as but not limited to an inversepower law model as seen below:ρ=A=B×v ^(−ρ)  (1)

For Equation (1), rho(ρ) is the fluid density, v is the volume, A, B andβ are optimized parameters when an inverse pumpout model is used.Without limitation, the parameters for other models may be more thanthree variables. It should be noted that parameterizing the pumpouttrends may include identifying how the trend is changing over time asfluid is being pumped out, where decaying exponential curves are trendsthat identify when fluid may become clean. Without limitation, otherpumpout models that may be used in block 408 may be arctan pumpoutmodels or double exponential models. In block 410, a correlation may bedeveloped that may include, but is not limited to, methods of machinelearning to the parameters of at least one of the pumpout trend model,formation properties, mud cake properties and fluid properties tocontamination. It should be noted that block 410 may also utilizemapping schemes that may allow for a prediction of output. For example,an output may be predicted based at least in part on the input.Additionally, machine learning may de-spike measured data, smoothmeasured data, and/or remove outliers. The correlation may map thecontamination at a certain area and may map any input value to thepumpout trend. Additionally, based on this input contamination of thefluid sample may be identified. It should be noted that the correlationmay be produced as an index. In block 412, input data for the model maybe captured and identified in real time. This is done to compute theformation properties such as formation pressure, drawdown mobility,difference between drawdown pressure and formation pressure and theoverbalance pressure.

In block 414, downhole fluid sampling tool 100 (e.g., referring to FIG.1 ) may acquire a fluid sample down hole. Additionally, downhole fluidsampling tool 100 may measure pumpout data including the accumulatedvolume and density. Additionally, downhole fluid sampling tool 100 maycompute optimized parameters of the pumpout density trend using theselected pumpout trend model. It should be noted that the optimizedparameters may be found and determined by fitting known shapes to shapesfound in real time during the pumpout. This optimization may change theinput to the inverse power trend. In block 416, measured and/or gatheredinput data including the formation properties and pumpout data, may beused in a correlation model to predict current contamination levels inthe pumpout. Block 416 may determine when in time there will be cleanformation fluid to take for a fluid sample. In block 418, a clean fluidsample may be taken, in part, based on the contamination leveldetermined by workflow 400. It should be noted, an acceptably lowcontaminated fluid sample, or clean fluid sample, is defined differentlyfor oils, volatile oils, and condensates. For example, an acceptably lowcontaminated fluid sample for oils is defined as having less than 5%contamination. For volatile oils, an acceptably low contaminated fluidsample is defined as having less than 2% contamination. For gascondensates, an acceptably low contaminated fluid sample is defined ashaving less than 1% contamination. According to McCain classification ofreservoir oil, it should be noted that a black oil is defined as oilhaving GOR less than 1000 scf/stb, API less than 45 and oil FVF lessthan 2 (low shrinkage oil). A volatile oil is defined as oil with GORbetween 1000 and 8000 scf/stb, API between 45 and 60 and oil FVF greaterthan 2 (high shrinkage oil). A gas condensate is defined as having GORbetween 70000 and 100000, API greater than 60 and is generally light incolor. An Oil-Based contaminate usually consist of C11-C29 componentsand will be dominated by paraffinic C14-C18 components. After a cleanfluid sample is taken or a clean fluid samples cannot be taken, thendownhole fluid sampling tool 100 may be moved to a new location andworkflow 400 may be repeated.

Workflow 400 may improve current technology because current methods mayonly use pumpout data to predict contamination. Using a combination offormation properties and pumpout data to predict contamination maypredict contamination with more accuracy and consistency compared withcurrent density fitting method. For example, existing density fittingmethod using arc tan fitting method rely end member properties which arenot measured directly in the laboratory or downhole. It should be notedthat end member properties are the absolute clear property of a cleanfluid sample. The end member properties are usually estimated as a rangevalue. Workflow 400 (e.g., referring to FIG. 4 ) does not rely noendmember properties. Additionally, workflow 400 may not be sensitive todata selection while the existing methods show such sensitivity.Workflow 400 as identified above allows for the use of pumpout data andformation properties in predicting contamination level of fluid samples.

The preceding description provides various embodiments of systems andmethods of use which may contain different method steps and alternativecombinations of components. It should be understood that, althoughindividual embodiments may be discussed herein, the present disclosurecovers all combinations of the disclosed embodiments, including, withoutlimitation, the different component combinations, method stepcombinations, and properties of the system.

Statement 1. A method may comprise positioning a downhole fluid samplingtool into a wellbore; performing a pressure test operation within thewellbore; performing a pumpout operation within the wellbore;identifying one or more formation parameters at least in part from theat least one pressure test operation or the at least one pumpoutoperation; building a correlation model that relates a pumpout trend tothe one or more formation parameters; determining a time when thedownhole fluid sampling tool takes a clean fluid sample utilizing atleast the correlation model; and acquiring the clean fluid sample withthe downhole fluid sampling tool from the wellbore.

Statement 2. The method of statement 1, further comprising generatingthe pumpout trend from the at least one pumpout operation.

Statement 3. The method of statement 2, further comprising optimizingthe one or more formation parameters with the pumpout trend.

Statement 4. The method of statements 2 or 3, further comprisingidentifying a contamination within the at least one pumpout operationfrom the pumpout trend.

Statement 5. The method of statements 1-4, further comprising relatingthe pumpout trend to the one or more formation parameters with adataset.

Statement 6. The method of statement 5, wherein the dataset includes oneor more samples from at least one location outside the wellbore.

Statement 7. The method of statements 5 or 6, wherein the datasetincludes data from one or more previous pumpout operations within thewellbore.

Statement 8. The method of statements 5-7, wherein the dataset includesa pumpout volume.

Statement 9. The method of statements 1-8, further comprising mappingthe contamination at an area.

Statement 10. The method of statements 1-9, wherein the clean fluidsample is found by using at least two properties of a fluid density, adrawdown mobility, a formation pressure, a drawdown and overbalancepressure, a formation property, or a predicted contamination value.

Statement 11. A system for estimating at least one of a clean fluidcomposition: a downhole fluid sampling tool configured to: perform apressure test operation within a wellbore; and perform a pumpoutoperation within the wellbore; and an information handling system for:building a correlation model that relates a pumpout trend to one or moreformation parameters; determining when the downhole fluid sampling toolmay take a clean fluid sample from at least the correlation model; andacquiring the clean fluid sample with the downhole fluid sampling toolfrom the wellbore.

Statement 12. The system of statement 11, wherein the informationhandling system further generates the pumpout trend from the pumpoutoperation.

Statement 13. The system of statement 12, wherein the informationhandling system further measures pumpout data including the accumulatedvolume and density.

Statement 14. The system of statements 11-13, wherein the informationhandling system further identifies a contamination within the pressuretest operation from the pumpout trend.

Statement 15. The system of statements 11-14, wherein the informationhandling system further relates the pumpout trend to the one or moreformation parameters with a dataset.

Statement 16. The system of statement 15, wherein the dataset includesone or more samples from at least one location outside the wellbore.

Statement 17. The system of statements 16 or 17, wherein the datasetincludes data from one or more previous pumpout operations within thewellbore.

Statement 18. The system of statements 15-17, wherein the datasetincludes a pumpout volume.

Statement 19. The system of statements 11-18, further comprising mappingthe contamination at a certain area.

Statement 20. The system of statements 11-19, wherein the clean fluidsample may be found by using at least two properties of a fluid density,a drawdown mobility, a formation pressure, a drawdown and overbalancepressure, a formation property, or a predicted contamination value.

It should be understood that the compositions and methods are describedin terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the elements that itintroduces.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, the disclosure covers all combinations of all thoseembodiments. Furthermore, no limitations are intended to the details ofconstruction or design herein shown, other than as described in theclaims below. Also, the terms in the claims have their plain, ordinarymeaning unless otherwise explicitly and clearly defined by the patentee.It is therefore evident that the particular illustrative embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the present disclosure. Ifthere is any conflict in the usages of a word or term in thisspecification and one or more patent(s) or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

The invention claimed is:
 1. A method comprising: positioning a downholefluid sampling tool into a wellbore; performing at least one pressuretest operation within the wellbore; performing at least one pumpoutoperation within the wellbore; identifying one or more formationparameters at least in part from the at least one pressure testoperation or the at least one pumpout operation; building a correlationmodel that relates a pumpout trend to the one or more formationparameters; determining a time when the downhole fluid sampling tooltakes a clean fluid sample utilizing at least the correlation model; andacquiring the clean fluid sample with the downhole fluid sampling toolfrom the wellbore.
 2. The method of claim 1, further comprisinggenerating the pumpout trend from the at least one pumpout operation. 3.The method of claim 2, further comprising optimizing the one or moreformation parameters with the pumpout trend.
 4. The method of claim 2,further comprising identifying a contamination within the at least onepumpout operation from the pumpout trend.
 5. The method of claim 1,further comprising relating the pumpout trend to the one or moreformation parameters with a dataset.
 6. The method of claim 5, whereinthe dataset includes one or more samples from at least one locationoutside the wellbore.
 7. The method of claim 5, wherein the datasetincludes data from one or more previous pumpout operations within thewellbore.
 8. The method of claim 5, wherein the dataset includes apumpout volume.
 9. The method of claim 4, further comprising mapping thecontamination at an area.
 10. The method of claim 1, wherein the cleanfluid sample is found by using at least two properties of a fluiddensity, a drawdown mobility, a formation pressure, a drawdown andoverbalance pressure, a formation property, or a predicted contaminationvalue.
 11. A system for estimating at least one of a clean fluidcomposition comprising: a downhole fluid sampling tool configured to:perform a pressure test operation within a wellbore; and perform apumpout operation within the wellbore; and an information handlingsystem for: building a correlation model that relates a pumpout trend toone or more formation parameters; determining when the downhole fluidsampling tool may take a clean fluid sample from at least thecorrelation model; and acquiring the clean fluid sample with thedownhole fluid sampling tool from the wellbore.
 12. The system of claim11, wherein the information handling system further generates thepumpout trend from the pumpout operation.
 13. The system of claim 12,wherein the information handling system further measures pumpout dataincluding an accumulated volume and density.
 14. The system of claim 12,wherein the information handling system further identifies acontamination within the pressure test operation from the pumpout trend.15. The system of claim 11, wherein the information handling systemfurther relates the pumpout trend to the one or more formationparameters with a dataset.
 16. The system of claim 15, wherein thedataset includes one or more samples from at least one location outsidethe wellbore.
 17. The system of claim 15, wherein the dataset includesdata from one or more previous pumpout operations within the wellbore.18. The system of claim 15, wherein the dataset includes a pumpoutvolume.
 19. The system of claim 14, further comprising mapping thecontamination at a certain area.
 20. The system of claim 11, wherein theclean fluid sample may be found by using at least two properties of afluid density, a drawdown mobility, a formation pressure, a drawdown andoverbalance pressure, a formation property, or a predicted contaminationvalue.